1. Field of the Invention
The present invention relates to a method for reducing the viscosity of clogging hydrocarbons in an oil well. A heat exchanger controls the flashing of heated feed water into steam until after the feed water is injected into the oil well which is left open to atmospheric pressure.
2. Description of the Prior Art
Heated oil has been employed for years to increase the production of oil wells that are marginal producers because they are clogged at their upper or more shallow extremity by high viscosity organic solids or hydrocarbons such as paraffins and asphaltenes. These chokes off normal reservoir oil flow.
The heated oil process is a comparatively low cost method for rejuvenating such oil wells. Heated oil is trucked to the well and introduced into the well in sufficient quantity, and over a sufficient period of time, that the well strings and adjacent formation are heated enough to increase the viscosity of the clogging hydrocarbons to the point that they will flow out of the well with the reservoir oil.
The hot oil process is only practical for clearing the upper portion of a well because heated oil quickly loses its thermal energy as it sinks deeper into the well.
Steam injection is another expedient that has been used to treat hydrocarbon clogging by thermal reduction of its viscosity, particularly hydrocarbons that plug the perforations or slotted liner where the formation meets the wellbore.
The characteristics of steam make it more effective than hot oil for this kind of treatment, and also for treating moderately deeper portions of a well. Since steam does not drop in temperature until it is completely condensed, its thermal effect passes deeper into the well, as compared to a heated liquid like hot oil. Its heat content per pound is about three times that of water.
Further, saturated steam occupies approximately sixty times the volume of water at the same temperature and pressure, and the resultant pressure acts upon the surrounding formation to aid in driving the reduced viscosity oil out of the formation.
In one steam injection process of the prior art, described in U.S. Pat. No. 3,288,214 issued to A. K. Winkler, feed water was used that contained significant quantities of minerals and impurities. To avoid having these impurities pass into and possibly clog the formation when the steam was injected into the well, a packer was placed in the casing string to increase formation pressures and thereby increase the pressure at which the injected feed water would be flashed into steam.
This arrangement reduced the extent of flashing or vaporization of feed water to no more than about twenty percent by weight. This apparently had the effect of limiting the carry over of impurities into the steam, but the degree of vaporization also significantly reduced the available steam. Consequently, the injected water and steam behaved more like hot water or the hot oil of the prior art and the advantages of using steam were diminished accordingly.
Another problem with the bulk of the prior art hydrocarbon unclogging steam injection systems is that they were not portable, the boiler or steam generator typically being located at a central location, with field piping extending from the steam generator through distribution manifolds to the various wells in an oil field.
Thermal losses in such a system are high, the costs are high, and the flexibility of a portable arrangement is lost.
Prior art oil well steam generation equipment also was characterized by low efficiencies resulting from poor boiler design. This in turn caused high operating costs, such that the cost advantage of steaming a clogged well often exceeded the economic benefits of improved production. There is a continuing need, therefore, for a practical system for stimulating secondary oil production at reasonable costs.